Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.06.007
Lihao Bian , Nan Wu , Zhongxian Cai
The exploration of deep layers has become increasingly important in the global oil and gas industry. The Tazhong-Bachu area of the Tarim Basin is a pioneering target for deep petroleum exploration in China, but only Wells Zhongshen1 and Zhongshen5 have found industrial oil flow in the Cambrian. Noteworthily, the occurrence of reservoir bitumen in the Lower Cambrian coring interval in many wells indicates that large-scale hydrocarbon migration had occurred here in geological history. Effective identification of reservoir bitumen in the Cambrian dolomite reservoirs is crucial to understanding hydrocarbons' distribution and migration. In this study, we adopt the Reservoir Bitumen Index (RBI) method to deduce a quantitative calculation formula for reservoir bitumen, and classify the transport system into four types based on differences in hydrocarbon transport behavior and characteristics. The results show that the deep carbonate low permeability-tight reservoirs of the Lower Cambrian in the Tazhong-Bachu area generally develop reservoir bitumen, most likely derived from underlying Precambrian source rocks. Therefore, the Lower Cambrian carbonate reservoir is considered a near-source discrete petroleum transport system, providing great potential for further oil and gas exploration in the Lower Paleozoic in the Tazhong-Bachu area.
{"title":"Identification and tracing of near-source petroleum transport system based on reservoir bitumen index (RBI) method: A case study of the lower cambrian in the Tazhong-Bachu area, Tarim Basin, China","authors":"Lihao Bian , Nan Wu , Zhongxian Cai","doi":"10.1016/j.ptlrs.2024.06.007","DOIUrl":"10.1016/j.ptlrs.2024.06.007","url":null,"abstract":"<div><div>The exploration of deep layers has become increasingly important in the global oil and gas industry. The Tazhong-Bachu area of the Tarim Basin is a pioneering target for deep petroleum exploration in China, but only Wells Zhongshen1 and Zhongshen5 have found industrial oil flow in the Cambrian. Noteworthily, the occurrence of reservoir bitumen in the Lower Cambrian coring interval in many wells indicates that large-scale hydrocarbon migration had occurred here in geological history. Effective identification of reservoir bitumen in the Cambrian dolomite reservoirs is crucial to understanding hydrocarbons' distribution and migration. In this study, we adopt the Reservoir Bitumen Index (RBI) method to deduce a quantitative calculation formula for reservoir bitumen, and classify the transport system into four types based on differences in hydrocarbon transport behavior and characteristics. The results show that the deep carbonate low permeability-tight reservoirs of the Lower Cambrian in the Tazhong-Bachu area generally develop reservoir bitumen, most likely derived from underlying Precambrian source rocks. Therefore, the Lower Cambrian carbonate reservoir is considered a near-source discrete petroleum transport system, providing great potential for further oil and gas exploration in the Lower Paleozoic in the Tazhong-Bachu area.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 45-56"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684775","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.08.005
Ali Alarbah, Arifur Rahman, Ezeddin Shirif, Na (Jenna) Jia
In recent years, the demand for heavy oil has increased due to its abundant availability and low cost. However, the extraction of heavy oil poses a significant challenge due to its high viscosity and low mobility. Therefore, various methods have been developed to enhance the recovery of heavy oil, including the use of catalysts. This study has created a unique simulation approach that uses liquid catalysts (LCs) to improve heavy oil recovery. In this work, laboratory testing dataset and numerical simulation studies were used to examine the potential of applying LCs as an alternative chemical agent for enhancing heavy oil recovery. CMG-STARS and CMOST modules were used to historical match the laboratory scale results of two sand-pack flooding experiments (water flooding and liquid catalyst flooding in tertiary recovery mode). Moreover, a sensitivity study was conducted to apply a wide range of assumptions to determine the most effective process controlling parameters. Finally, oil production optimization is performed using a genetic algorithm (particle swarm optimization) by selecting the optimum-operating parameters. In comparison to typical water flooding, the results revealed a discernible rise in the heavy oil recovery factor (RF) when injecting LCs. The simulation results showed that the optimized production strategy could increase the ultimate oil recovery by up to 45.06%. The injection rate, slug size, and injection temperature were found to be significant factors in optimizing the production of heavy oil. This simulation approach can be used to optimize the production of heavy oil using acidic Mo-Ni based liquid catalyst in different reservoirs.
{"title":"Production optimization of heavy oil recovery utilizing Mo-Ni based liquid catalysts: A simulation approach","authors":"Ali Alarbah, Arifur Rahman, Ezeddin Shirif, Na (Jenna) Jia","doi":"10.1016/j.ptlrs.2024.08.005","DOIUrl":"10.1016/j.ptlrs.2024.08.005","url":null,"abstract":"<div><div>In recent years, the demand for heavy oil has increased due to its abundant availability and low cost. However, the extraction of heavy oil poses a significant challenge due to its high viscosity and low mobility. Therefore, various methods have been developed to enhance the recovery of heavy oil, including the use of catalysts. This study has created a unique simulation approach that uses liquid catalysts (LCs) to improve heavy oil recovery. In this work, laboratory testing dataset and numerical simulation studies were used to examine the potential of applying LCs as an alternative chemical agent for enhancing heavy oil recovery. CMG-STARS and CMOST modules were used to historical match the laboratory scale results of two sand-pack flooding experiments (water flooding and liquid catalyst flooding in tertiary recovery mode). Moreover, a sensitivity study was conducted to apply a wide range of assumptions to determine the most effective process controlling parameters. Finally, oil production optimization is performed using a genetic algorithm (particle swarm optimization) by selecting the optimum-operating parameters. In comparison to typical water flooding, the results revealed a discernible rise in the heavy oil recovery factor (RF) when injecting LCs<strong>.</strong> The simulation results showed that the optimized production strategy could increase the ultimate oil recovery by up to 45.06%. The injection rate, slug size, and injection temperature were found to be significant factors in optimizing the production of heavy oil. This simulation approach can be used to optimize the production of heavy oil using acidic Mo-Ni based liquid catalyst in different reservoirs.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 57-65"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684776","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.08.003
Sen Chen , Hongjuan You , Jinshan Xu , Maoan Wei , Tirun Xu , He Wang
Whether the oil and gas fields in the Carbon Capture, Utilization, and Storage (CCUS) project use underground storage or energy supplementation to enhance oil recovery, they must be injected or monitored through the wellbore. Thus, the foundation and requirement for the safety of carbon dioxide (CO2) storage is the wellbore's integrity. When CO2 is dissolved in water, carbonic acid is created, and this acid strongly corrodes underground pipes. Therefore, the integrity issue with CO2 injection wells is more noticeable than with other wellbores. An annular pressure during gas injection is the primary symptom of gas injection string leakage in CO2 injection wells. This study aims to provide real-time pipe string monitoring using a distributed optical fiber temperature sensing system (DTS) and a distributed optical fiber acoustic sensing system (DAS). Variations in temperature and vibration are caused by annulus pressure relief or gas injection. Optical fiber logging, in contrast to traditional logging, has better performance indicators for optical fiber sensing apparatus. To adapt to complex wellbore conditions, it is necessary to enhance the temperature accuracy of DTS and the sensitivity and signal-to-noise ratio of DAS in CO2 drive injection wells based on the features of the gas injection string. To differentiate the leakage signal from the regular fluid flow signal, the energy calculation in the frequency band is done for DAS based on noise reduction, and the signal processing in the frequency band is done by the spectrum characteristics of the CO2 wellbore signal. The translation invariant wavelet algorithm is the primary denoising method for DTS, overcoming the shortcomings of traditional wavelet threshold algorithms such as excessive smoothing and the pseudo-Gibbs phenomenon. Furthermore, the depth correction during the optical cable lowering process is also examined in this paper. A CO2 gas injection well field experiment was conducted using this technology. A 1671m well was dug, and 1631m of optical cable were installed in the tubing. The tubing leakage position was successfully identified through gas injection, annulus pressure relief, and a comparison of DAS and DTS data. The field results demonstrate the accuracy with which the gas injection string integrity can be accurately monitored in real-time using distributed optical fiber sensing technology for CO2 injection wells.
{"title":"Leakage monitoring of carbon dioxide injection well string using distributed optical fiber sensor","authors":"Sen Chen , Hongjuan You , Jinshan Xu , Maoan Wei , Tirun Xu , He Wang","doi":"10.1016/j.ptlrs.2024.08.003","DOIUrl":"10.1016/j.ptlrs.2024.08.003","url":null,"abstract":"<div><div>Whether the oil and gas fields in the Carbon Capture, Utilization, and Storage (CCUS) project use underground storage or energy supplementation to enhance oil recovery, they must be injected or monitored through the wellbore. Thus, the foundation and requirement for the safety of carbon dioxide (CO<sub>2</sub>) storage is the wellbore's integrity. When CO<sub>2</sub> is dissolved in water, carbonic acid is created, and this acid strongly corrodes underground pipes. Therefore, the integrity issue with CO<sub>2</sub> injection wells is more noticeable than with other wellbores. An annular pressure during gas injection is the primary symptom of gas injection string leakage in CO<sub>2</sub> injection wells. This study aims to provide real-time pipe string monitoring using a distributed optical fiber temperature sensing system (DTS) and a distributed optical fiber acoustic sensing system (DAS). Variations in temperature and vibration are caused by annulus pressure relief or gas injection. Optical fiber logging, in contrast to traditional logging, has better performance indicators for optical fiber sensing apparatus. To adapt to complex wellbore conditions, it is necessary to enhance the temperature accuracy of DTS and the sensitivity and signal-to-noise ratio of DAS in CO<sub>2</sub> drive injection wells based on the features of the gas injection string. To differentiate the leakage signal from the regular fluid flow signal, the energy calculation in the frequency band is done for DAS based on noise reduction, and the signal processing in the frequency band is done by the spectrum characteristics of the CO<sub>2</sub> wellbore signal. The translation invariant wavelet algorithm is the primary denoising method for DTS, overcoming the shortcomings of traditional wavelet threshold algorithms such as excessive smoothing and the pseudo-Gibbs phenomenon. Furthermore, the depth correction during the optical cable lowering process is also examined in this paper. A CO<sub>2</sub> gas injection well field experiment was conducted using this technology. A 1671m well was dug, and 1631m of optical cable were installed in the tubing. The tubing leakage position was successfully identified through gas injection, annulus pressure relief, and a comparison of DAS and DTS data. The field results demonstrate the accuracy with which the gas injection string integrity can be accurately monitored in real-time using distributed optical fiber sensing technology for CO<sub>2</sub> injection wells.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 166-177"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684815","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.08.002
Layal Fadhil AL-Kaaby , Sina Rashidi , Reza Ghamarpoor , Seyednooroldin Hosseini , Hasan N. Al-Saedi , Elias Ghaleh Golab
The stability of the drilled wellbores in carbonate formations is of great importance. This paper is a new approach to determine the elastic properties of the wellbore based on rock physics methods using the Hashin-Shtrikman bounds to determine the wellbore stability. Initially, the static elastic parameters were determined by two different methods, namely the rock physics method and DSI log, followed by clustering through Multi-Resolutional Graph-Based clustering (MRGC) and calculating geomechanical-units (GMUs) of each method separately. The obtained results from DSI log and rock physic methods were then compared followed by determining the wellbore stability. The results showed that the correlation between shear and compressional wave velocity obtained from the petrophysical method with the measured values of shear and pressure wave velocity in the well was 0.94 and 0.90, respectively, which shows that the petrophysical method can estimate these two logs with high accuracy, and it can be a suitable alternative instead of using the Dipole Shear Sonic Imager (DSI). It was observed that the geomechanical units of elastic parameters calculated by proposed rock physics method are in good agreement with those obtained from DSI log. Rock-physic method can be a good alternative for when expensive DSI logs are missing.
{"title":"Determining the geomechanical units using rock physics methods","authors":"Layal Fadhil AL-Kaaby , Sina Rashidi , Reza Ghamarpoor , Seyednooroldin Hosseini , Hasan N. Al-Saedi , Elias Ghaleh Golab","doi":"10.1016/j.ptlrs.2024.08.002","DOIUrl":"10.1016/j.ptlrs.2024.08.002","url":null,"abstract":"<div><div>The stability of the drilled wellbores in carbonate formations is of great importance. This paper is a new approach to determine the elastic properties of the wellbore based on rock physics methods using the Hashin-Shtrikman bounds to determine the wellbore stability. Initially, the static elastic parameters were determined by two different methods, namely the rock physics method and DSI log, followed by clustering through Multi-Resolutional Graph-Based clustering (MRGC) and calculating geomechanical-units (GMUs) of each method separately. The obtained results from DSI log and rock physic methods were then compared followed by determining the wellbore stability. The results showed that the correlation between shear and compressional wave velocity obtained from the petrophysical method with the measured values of shear and pressure wave velocity in the well was 0.94 and 0.90, respectively, which shows that the petrophysical method can estimate these two logs with high accuracy, and it can be a suitable alternative instead of using the Dipole Shear Sonic Imager (DSI). It was observed that the geomechanical units of elastic parameters calculated by proposed rock physics method are in good agreement with those obtained from DSI log. Rock-physic method can be a good alternative for when expensive DSI logs are missing.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 178-187"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684816","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.07.006
Zhujiang Liu , Zhenxue Jiang , Fubin Wei , Tao Yuan , Fei Li
Deep shale gas has become an important frontier for future shale gas exploration and development. The Wufeng-Longmaxi formations in southern China have undergone complex tectonic and transformation through multi-stage tectonic movements. Deep shale gas enrichment conditions are complex, which greatly restricts the exploration and development of deep shale gas. In this study, based on systematic analysis of basic geological characteristics and gas reservoir characteristics of deep shales, the main factors controlling deep shale gas enrichment in southern China were investigated, and enrichment modes were established. The results show that high-quality shales were developed in the deep-water continental shelf facies, characterized by moderate thermal maturity, high silica content, and abundant organic matter. These characteristics provide a good basis for the formation and enrichment of shale gas. The deep shale gas reservoir is featured by overpressure, high porosity and high gas content. The development and maintenance of high porosity, favorable roof and floor sealing conditions, and weak tectonic activity during uplift stage are the main factors to control deep shale gas enrichment. Based on a comprehensive analysis, the enrichment modes of deep shale gas under three different tectonic patterns were established, namely overpressure enrichment within the basin, overpressure enrichment in the faulted nose or slope of the margin, and overpressure enrichment in the remnant syncline outside the basin. This study provides a reference for exploration and development of deep shale gas in Sichuan Basin and other areas.
{"title":"Shale gas accumulation mechanism of deep-buried marine shale of Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation in the southeast Sichuan Basin","authors":"Zhujiang Liu , Zhenxue Jiang , Fubin Wei , Tao Yuan , Fei Li","doi":"10.1016/j.ptlrs.2024.07.006","DOIUrl":"10.1016/j.ptlrs.2024.07.006","url":null,"abstract":"<div><div>Deep shale gas has become an important frontier for future shale gas exploration and development. The Wufeng-Longmaxi formations in southern China have undergone complex tectonic and transformation through multi-stage tectonic movements. Deep shale gas enrichment conditions are complex, which greatly restricts the exploration and development of deep shale gas. In this study, based on systematic analysis of basic geological characteristics and gas reservoir characteristics of deep shales, the main factors controlling deep shale gas enrichment in southern China were investigated, and enrichment modes were established. The results show that high-quality shales were developed in the deep-water continental shelf facies, characterized by moderate thermal maturity, high silica content, and abundant organic matter. These characteristics provide a good basis for the formation and enrichment of shale gas. The deep shale gas reservoir is featured by overpressure, high porosity and high gas content. The development and maintenance of high porosity, favorable roof and floor sealing conditions, and weak tectonic activity during uplift stage are the main factors to control deep shale gas enrichment. Based on a comprehensive analysis, the enrichment modes of deep shale gas under three different tectonic patterns were established, namely overpressure enrichment within the basin, overpressure enrichment in the faulted nose or slope of the margin, and overpressure enrichment in the remnant syncline outside the basin. This study provides a reference for exploration and development of deep shale gas in Sichuan Basin and other areas.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 137-148"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684778","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.08.004
Amit Verma , Nilanjan Pal , Narendra Kumar , Ahmed Al-Yaseri , Muhammad Ali , Keka Ojha
Nanoparticles stabilized foam fracturing fluid is an emerging technology in the field of hydraulic fracturing for the unconventional reservoirs. Hydraulic fracturing, commonly known as fracking, is a process used to extract oil and gas from the unconventional reservoirs, such as shale formations. This study has reviewed contiguous improvement in the properties of foam fracturing fluid by the effective formulation of surfactant, polymer, and nanoparticles. Compared to conventional fracturing fluids (slick water and polymer), nanoparticles stabilized foam fracturing fluids exhibit superior proppant-carrying capabilities, ensuring better penetration into micro-fractures and enhanced contact with the reservoir matrix, reduce water usage, and minimize formation damage. Foam structures at different scales, i.e., the interface between air-water and liquid film has been discussed in depth to elaborate on the mechanisms that maintain the stability of foam film. The effects of nanoparticles for improving the foam stability and liquid drainage are deliberated to throw light on the strength and limitations of the current review work for better knowledge of foam structure. This review work is on the advancement of nanoparticles foam fluid focuses on significant analyses, problems, future scope, and applications. The various knowledge gaps and conflicting observations have been identified that give the range of our studies. The technical challenges of using foam-based fracturing fluids were also explored. Maintaining foam stability at the high pressures and temperatures experienced in unconventional reservoirs is a critical challenge. The potential for foam collapse or degradation could undermine its effectiveness in delivering proppants and stimulating fractures.
{"title":"Nanoparticles stabilized foam fluid for hydraulic fracturing application of unconventional gas reservoirs: A review of the properties, progress and future prospects","authors":"Amit Verma , Nilanjan Pal , Narendra Kumar , Ahmed Al-Yaseri , Muhammad Ali , Keka Ojha","doi":"10.1016/j.ptlrs.2024.08.004","DOIUrl":"10.1016/j.ptlrs.2024.08.004","url":null,"abstract":"<div><div>Nanoparticles stabilized foam fracturing fluid is an emerging technology in the field of hydraulic fracturing for the unconventional reservoirs. Hydraulic fracturing, commonly known as fracking, is a process used to extract oil and gas from the unconventional reservoirs, such as shale formations. This study has reviewed contiguous improvement in the properties of foam fracturing fluid by the effective formulation of surfactant, polymer, and nanoparticles. Compared to conventional fracturing fluids (slick water and polymer), nanoparticles stabilized foam fracturing fluids exhibit superior proppant-carrying capabilities, ensuring better penetration into micro-fractures and enhanced contact with the reservoir matrix, reduce water usage, and minimize formation damage. Foam structures at different scales, i.e., the interface between air-water and liquid film has been discussed in depth to elaborate on the mechanisms that maintain the stability of foam film. The effects of nanoparticles for improving the foam stability and liquid drainage are deliberated to throw light on the strength and limitations of the current review work for better knowledge of foam structure. This review work is on the advancement of nanoparticles foam fluid focuses on significant analyses, problems, future scope, and applications. The various knowledge gaps and conflicting observations have been identified that give the range of our studies. The technical challenges of using foam-based fracturing fluids were also explored. Maintaining foam stability at the high pressures and temperatures experienced in unconventional reservoirs is a critical challenge. The potential for foam collapse or degradation could undermine its effectiveness in delivering proppants and stimulating fractures.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 149-165"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684814","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.07.004
Mohammad A. Abdelwahhab , Emad H. Ali , Nabil A. Abdelhafez
Estuarine-systems, developed upon transgressive-phases, feature high-quality reservoir-facies, e.g. tidal-bars, that are important stratigraphic-plays critical for hydrocarbon exploration-development. However, capturing their intricate architectural elements (heterogeneity and quality) is still challenging due to the complex stacking-nature and limited-examples. Moreover, defining reservoir-boundaries upon static-modeling of reservoirs cannot be efficient unless it is controlled by stratal-geometries and established depositional-models. To this end, in this study, we performed 3D-static geocellular reservoir-modeling process for the Late-Cenomanian AbuRoash“G” Member (Abu-Gharadig Basin, Egypt) with sequence-stratigraphic and geomodel, relative-geological-time (RGT) model and horizon-stacks, constraints. In this investigation, as an effective-workflow, not only facies-analysis, integrating seismic-stratigraphy and GR-log motifs, was applied for paleo-environment reconstruction, but also machine learning-based electrofacies were applied, through self-organized-maps (SOM), to accurately recognize complex facies-assemblages present. Object-based and pixel-based stochastic-simulation processes were applied upon geocellularly modeling rock and fluid properties, utilizing key-information scales of seismic and well-log data. The results show that three third-order depositional sequences dominate the succession, resting on the Late-Cretaceous unconformity, of which sequence-1 encloses the lowstand and transgressive systems-tracts of the fluvio-estuarine Bahariya and Abu Roash“G” units, respectively. The transgressive phase built AbuRoash“G” lithounit features an estuarine depositional-system encompassing four facies-associations, of which tidal-sand-bars represent significant gas-bearing reservoir-quality facies. The tidal-bar facies’ efficient reservoir quality calls for attention and testing in future development plans and investigation in similar settings. Furthermore, the facies-constrained workflow established in this study, for reservoir modeling, can effectively help identify the ultimate reservoir-configuration worldwide, as long as the 3D-static modeling process is controlled by the stratal and geomodel restraints.
{"title":"Electrofacies-driven 3D-static reservoir modeling of the Late Cenomanian AbuRoash’G Member (Abu-Gharadig Basin, Egypt): Sequence stratigraphic and geomodel constraints for a gas-bearing estuarine system","authors":"Mohammad A. Abdelwahhab , Emad H. Ali , Nabil A. Abdelhafez","doi":"10.1016/j.ptlrs.2024.07.004","DOIUrl":"10.1016/j.ptlrs.2024.07.004","url":null,"abstract":"<div><div>Estuarine-systems, developed upon transgressive-phases, feature high-quality reservoir-facies, e.g. tidal-bars, that are important stratigraphic-plays critical for hydrocarbon exploration-development. However, capturing their intricate architectural elements (heterogeneity and quality) is still challenging due to the complex stacking-nature and limited-examples. Moreover, defining reservoir-boundaries upon static-modeling of reservoirs cannot be efficient unless it is controlled by stratal-geometries and established depositional-models. To this end, in this study, we performed 3D-static geocellular reservoir-modeling process for the Late-Cenomanian AbuRoash“G” Member (Abu-Gharadig Basin, Egypt) with sequence-stratigraphic and geomodel, relative-geological-time (RGT) model and horizon-stacks, constraints. In this investigation, as an effective-workflow, not only facies-analysis, integrating seismic-stratigraphy and GR-log motifs, was applied for paleo-environment reconstruction, but also machine learning-based electrofacies were applied, through self-organized-maps (SOM), to accurately recognize complex facies-assemblages present. Object-based and pixel-based stochastic-simulation processes were applied upon geocellularly modeling rock and fluid properties, utilizing key-information scales of seismic and well-log data. The results show that three third-order depositional sequences dominate the succession, resting on the Late-Cretaceous unconformity, of which sequence-1 encloses the lowstand and transgressive systems-tracts of the fluvio-estuarine Bahariya and Abu Roash“G” units, respectively. The transgressive phase built AbuRoash“G” lithounit features an estuarine depositional-system encompassing four facies-associations, of which tidal-sand-bars represent significant gas-bearing reservoir-quality facies. The tidal-bar facies’ efficient reservoir quality calls for attention and testing in future development plans and investigation in similar settings. Furthermore, the facies-constrained workflow established in this study, for reservoir modeling, can effectively help identify the ultimate reservoir-configuration worldwide, as long as the 3D-static modeling process is controlled by the stratal and geomodel restraints.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 79-104"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141849504","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.06.008
Yunhua Deng, Yongcai Yang, Ting Yang
Crude oil and natural gas are generated by organic matters in rocks in sedimentary basins. After incisive and systematic research on global petroliferous basins, it is realized that the distribution of oil and gas fields is highly heterogeneous, and most of oil and gas are enriched in a few sedimentary strata. Source rocks are the most significant factor that governs the distribution of crude oil and natural gas in sedimentary basins. The prerequisite to finding out a petroliferous basin is to search for source rocks. The abundance of organic matters determines the quality of source rocks and the quantity of generated hydrocarbons. In a sedimentary basin, the biological nutrients come from rivers. The biological nutrition is the key factor that controls the degree of reproduction and organic matter abundance in source rocks, which is a governing factor for the amount of oil and gas generated and the degree of petroleum resource enrichment in the sedimentary basin. Oil and gas are mainly distributed in three systems in the world: river-lake system, river-gulf system and river-delta system. The river-lake system is the main location of continental oil distribution. Lacustrine oil is mainly produced by organic matters originating from dead algae in lakes preserved in sedimentary rocks. Algae growth mainly depends on the nutrients that come from rivers, especially those with a long history, flowing through a wide area. The nutrients have a large amount of phosphorus, potassium and other minerals dissolved in water, providing a prerequisite to the growth of algae and a guarantee of the formation of high-quality source rocks. The river-gulf system is the main location of marine oil distribution. The gulf is the estuary of the river, which brings abundant minerals to promote the growth and proliferation of aquatic organisms such as algae. Gulfs are relatively closed and their exchange with the ocean is restricted, therefore the gulf is also conducive to the preservation of organic matters. The coaliferous gas has the world's most widely distributed and biggest reserves; many giant coaliferous gas fields are located in the river-delta system. The sediments brought by the river are fertile soil for the growth of higher plants, and the native higher plants on the river-delta plain are the solid material basis for the formation of coal-measure gas source rocks. Well-developed delta reservoirs with good reservoir-caprock configuration are beneficial for natural gas enrichment and accumulation.
{"title":"Three systems of the oil and gas formation in the world","authors":"Yunhua Deng, Yongcai Yang, Ting Yang","doi":"10.1016/j.ptlrs.2024.06.008","DOIUrl":"10.1016/j.ptlrs.2024.06.008","url":null,"abstract":"<div><div>Crude oil and natural gas are generated by organic matters in rocks in sedimentary basins. After incisive and systematic research on global petroliferous basins, it is realized that the distribution of oil and gas fields is highly heterogeneous, and most of oil and gas are enriched in a few sedimentary strata. Source rocks are the most significant factor that governs the distribution of crude oil and natural gas in sedimentary basins. The prerequisite to finding out a petroliferous basin is to search for source rocks. The abundance of organic matters determines the quality of source rocks and the quantity of generated hydrocarbons. In a sedimentary basin, the biological nutrients come from rivers. The biological nutrition is the key factor that controls the degree of reproduction and organic matter abundance in source rocks, which is a governing factor for the amount of oil and gas generated and the degree of petroleum resource enrichment in the sedimentary basin. Oil and gas are mainly distributed in three systems in the world: river-lake system, river-gulf system and river-delta system. The river-lake system is the main location of continental oil distribution. Lacustrine oil is mainly produced by organic matters originating from dead algae in lakes preserved in sedimentary rocks. Algae growth mainly depends on the nutrients that come from rivers, especially those with a long history, flowing through a wide area. The nutrients have a large amount of phosphorus, potassium and other minerals dissolved in water, providing a prerequisite to the growth of algae and a guarantee of the formation of high-quality source rocks. The river-gulf system is the main location of marine oil distribution. The gulf is the estuary of the river, which brings abundant minerals to promote the growth and proliferation of aquatic organisms such as algae. Gulfs are relatively closed and their exchange with the ocean is restricted, therefore the gulf is also conducive to the preservation of organic matters. The coaliferous gas has the world's most widely distributed and biggest reserves; many giant coaliferous gas fields are located in the river-delta system. The sediments brought by the river are fertile soil for the growth of higher plants, and the native higher plants on the river-delta plain are the solid material basis for the formation of coal-measure gas source rocks. Well-developed delta reservoirs with good reservoir-caprock configuration are beneficial for natural gas enrichment and accumulation.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 1-27"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143684774","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-03-01DOI: 10.1016/j.ptlrs.2024.07.001
Yusuf Falola , Polina Churilova , Rui Liu , Chung-Kan Huang , Jose F. Delgado , Siddharth Misra
Geological model compression is crucial for making large and complex models more manageable. By reducing the size of these models, compression techniques enable efficient storage, enhance computational efficiency, making it feasible to perform complex simulations and analyses in a shorter time. This is particularly important in applications such as reservoir management, groundwater hydrology, and geological carbon storage, where large geomodels with millions of grid cells are common. This study presents a comprehensive overview of previous work on geomodel compression and introduces several autoencoder-based deep-learning architectures for low-dimensional representation of modified Brugge-field geomodels. The compression and reconstruction efficiencies of autoencoders (AE), variational autoencoders (VAE), vector-quantized variational autoencoders (VQ-VAE), and vector-quantized variational autoencoders 2 (VQ-VAE2) were tested and compared to the traditional singular value decomposition (SVD) method. Results show that the deep-learning-based approaches significantly outperform SVD, achieving higher compression ratios while maintaining or even exceeding the reconstruction quality. Notably, VQ-VAE2 achieves the highest compression ratio of 667:1 with a structural similarity index metric (SSIM) of 0.92, far surpassing the 10:1 compression ratio of SVD with a SSIM of 0.9. The result of this work shows that, unlike traditional approaches, which often rely on linear transformations and can struggle to capture complex, non-linear relationships within geological data, VQ-VAE's use of vector quantization helps in preserving high-resolution details and enhances the model's ability to generalize across varying geological complexities.
{"title":"Generating extremely low-dimensional representation of subsurface earth models using vector quantization and deep Autoencoder","authors":"Yusuf Falola , Polina Churilova , Rui Liu , Chung-Kan Huang , Jose F. Delgado , Siddharth Misra","doi":"10.1016/j.ptlrs.2024.07.001","DOIUrl":"10.1016/j.ptlrs.2024.07.001","url":null,"abstract":"<div><div>Geological model compression is crucial for making large and complex models more manageable. By reducing the size of these models, compression techniques enable efficient storage, enhance computational efficiency, making it feasible to perform complex simulations and analyses in a shorter time. This is particularly important in applications such as reservoir management, groundwater hydrology, and geological carbon storage, where large geomodels with millions of grid cells are common. This study presents a comprehensive overview of previous work on geomodel compression and introduces several autoencoder-based deep-learning architectures for low-dimensional representation of modified Brugge-field geomodels. The compression and reconstruction efficiencies of autoencoders (AE), variational autoencoders (VAE), vector-quantized variational autoencoders (VQ-VAE), and vector-quantized variational autoencoders 2 (VQ-VAE2) were tested and compared to the traditional singular value decomposition (SVD) method. Results show that the deep-learning-based approaches significantly outperform SVD, achieving higher compression ratios while maintaining or even exceeding the reconstruction quality. Notably, VQ-VAE2 achieves the highest compression ratio of 667:1 with a structural similarity index metric (SSIM) of 0.92, far surpassing the 10:1 compression ratio of SVD with a SSIM of 0.9. The result of this work shows that, unlike traditional approaches, which often rely on linear transformations and can struggle to capture complex, non-linear relationships within geological data, VQ-VAE's use of vector quantization helps in preserving high-resolution details and enhances the model's ability to generalize across varying geological complexities.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"10 1","pages":"Pages 28-44"},"PeriodicalIF":0.0,"publicationDate":"2025-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141696236","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-09-01DOI: 10.1016/j.ptlrs.2024.03.002
In this study, Hypermesh and LS-DYNA numerical simulation software are used to build a multi domain coupling model of natural gas pipeline, including soil, pipeline, TNT explosive and air domain, and the non-reflection boundary conditions are set for the model. The TNT equivalent method is used to convert the physical explosion amount of natural gas pipeline into 1387.38 kg TNT explosive amount. The simulation results show that the physical explosion of pipeline forms an approximate elliptical crater with a width of 12.68 m and a depth of 4.12 m; the TNT equivalent of the model is corrected by comparing the crater simulation value and the size value of the crater calculated by the PRCI empirical formula under the same laying condition, and the correction coefficient is selected as 0.9, and the corrected TNT equivalent is 1248.64 kg; the modified model crater size is 3.72 m deep and 12.66 m wide, compared with the crater size obtained from the field test, the error of crater depth and width calculated by the modified model simulation is 5.7% and 15.5% respectively.
{"title":"Research on physical explosion crater model of high-pressure natural gas pipeline","authors":"","doi":"10.1016/j.ptlrs.2024.03.002","DOIUrl":"10.1016/j.ptlrs.2024.03.002","url":null,"abstract":"<div><p>In this study, Hypermesh and LS-DYNA numerical simulation software are used to build a multi domain coupling model of natural gas pipeline, including soil, pipeline, TNT explosive and air domain, and the non-reflection boundary conditions are set for the model. The TNT equivalent method is used to convert the physical explosion amount of natural gas pipeline into 1387.38 kg TNT explosive amount. The simulation results show that the physical explosion of pipeline forms an approximate elliptical crater with a width of 12.68 m and a depth of 4.12 m; the TNT equivalent of the model is corrected by comparing the crater simulation value and the size value of the crater calculated by the PRCI empirical formula under the same laying condition, and the correction coefficient is selected as 0.9, and the corrected TNT equivalent is 1248.64 kg; the modified model crater size is 3.72 m deep and 12.66 m wide, compared with the crater size obtained from the field test, the error of crater depth and width calculated by the modified model simulation is 5.7% and 15.5% respectively.</p></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"9 3","pages":"Pages 432-438"},"PeriodicalIF":0.0,"publicationDate":"2024-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2096249524000279/pdfft?md5=3e92fe2993143a2ce8dbb0baabd94cba&pid=1-s2.0-S2096249524000279-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140269777","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
扫码关注我们
求助内容：
应助结果提醒方式：
京公网安备 11010802042870号